1. Field of the Invention
This invention relates to a process utilizing a well or wells and includes the steps of testing or measuring formation fluids. More specifically, this invention relates to a method for determining the fluid saturations of an immobile fluid phase and at least one mobile fluid phase in a subterranean reservoir.
2. Description of the Prior Art
A typical oil-productive formation is a stratum of rock containing tiny interconnected pore spaces which are saturated with oil, water and gas. Knowledge of the relative amounts of these fluids in the formation is indispensable to proper and efficient production of the formation oil. When a formation is first drilled, it is necessary to know the original oil saturation to intelligently plan the future exploitation of the field. In tertiary recovery techniques, such as in solvent flooding, the quantity of oil present in the formation will often dictate the most efficient manner of conducting such an operation.
It is also desirable to know the gas saturation in a formation which is flooded by water or oil. As gas is withdrawn from a formation containing gas and at least one other mobile liquid such as formation brine or crude oil, the mobile liquid replaces the space formerly occupied by the produced gas. Laboratory and field tests have shown, however, that large quantities of gas remain trapped in the formation. This unproduced gas represents the natural gas saturation which is unable to flow because there is no longer any permeability to gas due to the gas-water saturation relationship. Once the formation is filled with brine or oil, from one-tenth to one-half of the initial gas volume is potentially lost as a residual phase. It is generally desirable, therefore, to know the residual gas saturation in the portion of the formation flooded by water to estimate the recoverable gas in the unflooded portion of the formation.
There are several methods which are currently used to obtain the fluid saturation of a formation. Coring, one technique used for acquiring this information, is a direct sampling of the formation rock and liquids. For example, a small segment of the formation rock saturated with fluids is cored from the formation and removed to the earth's surface where its fluid saturation can be analyzed. This method, however, is susceptible to the faults of the sampling technique; thus, a sample taken may or may not be representative of the formation as a whole. Also, there is a genuine possibility that the coring process itself may change the fluid saturation of the extracted core. For example, in the coring process the fluid pressure may vary from reservoir conditions and this may cause the gas saturation to change. Moreover, coring can only be employed in newly drilled wells or open hole completions. In the vast majority of wells casing is set through the gas-bearing formation when the well is initially completed. Core samples, therefore, cannot subsequently be obtained from such a well. Finally, coring by its very nature only investigates the properties of the formation rock and fluids in the immediate vicinity of the wellbore.
Another approach for obtaining reservoir fluid saturations is by logging techniques. These techniques also investigate formation rock and fluid properties for only a short distance beyond the wellbore. These techniques study the rock fluid system as an entity; it is often difficult by this approach to differentiate between the properties of the rock and its fluids.
Material balance calculations based on production history are another approach to the problem. Estimates of fluid saturation acquired by this method are subjected to even more variables than coring or logging. The technique requires a knowledge of initial fluid saturation of a formation by some other method and knowledge of the source of the recovered fluid.
More recent methods for determining fluid saturation in a subterranean formation are concerned with injection and production of trace chemicals into and out of the formation. For example, as proposed in U.S. Pat. No. 3,590,932 issued July 6, 1971 to C. E. Cooke, Jr., a carrier fluid containing at least two tracers having different partition coefficients between the immobile fluid and the aqueous fluid containing the tracers is injected into one location in the formation and produced from another. Due to the different partition coefficients of the tracers, they will be chromatographically separated as they pass through the formation, and this chromatographic separation is a function of the saturation of the immobile fluid phase. In another example, as suggested in U.S. Pat. No. 3,623,842 issued Nov. 30, 1971 to H. A. Deans, a carrier fluid containing a reactive chemical substance is injected into the formation through a well. The carrier fluid reactant solution is displaced into the formation, and the well is shut-in to permit the reactant to undergo a chemical change to produce additional tracer materials having different partition coefficients. When the well is produced, the tracers having different partition coefficients are chromatographically separated, and the degree of separation may be used to determine the residual fluid saturation in the formation. In still another example, as proposed in U.S. Pat. No. 3,856,468 issued Dec. 24, 1974 to Keller, residual gas saturation in a subterranean formation containing at least one mobile fluid phase can be determined. In this method, brine which is miscible with the formation brine and contains low concentrations of at least two chemical substances is injected into the formation through a well and displaced into the formation away from the well. One of these substances is a precursor that reacts in the formation to form two substances. One substance is a tracer material that partitions between the gas phase and brine differently than the precursor and the other substance is a substantially nonreactive tracer material. The well is shut-in for a period sufficient for the precursor to react, and the well thereafter is returned to production. The produced fluids are analyzed for the presence of the tracer materials and the gas saturation of the formation is determined by applying principles of chromatography. However, the use of trace chemicals to determine the residual gas saturation is subject to certain drawbacks. A principal problem with these methods is that the chromatographic separation of the trace chemicals due to their solubility in the gaseous phase can be so small that the measured results can be extremely difficult to analyze.